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While formation damage is typically a problem affecting the productivity of well, it can also pose problems for injection. Understanding the causes of this type of formation damage is important so that efforts to prevent it can be undertaken. This page discusses the types of formation damage that affect injection wells. In such projects, the cost of piping and pumping the water is determined primarily by reservoir depth and the source of the water. However, water treatment costs can vary substantially, depending on the water quality required.
Yu, Haiyang (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum) | Chen, Zhewei (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum) | Yang, Zhonglin (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum) | Cheng, Shiqing (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum) | He, Youan (Research Institute of Exploration and Development, Petro China Changqing Oilfield Company) | Xian, Bo (Development Department, Tarim Oilfield Company, PetroChina)
Abstract Poor energy supplement and low hydrocarbon recovery are the two main shortcomings for water or gas injection in tight oil reservoir development. Horizontal well flooding can improve oil recovery and sweep efficiency of water flooding. However, the economic benefits need to be considered for long horizonal well injection. Based on a case of Changqing Oil filed, this paper presents a novel development approach, Allied In-Situ Injection and Production (AIIP), for fractured horizontal wells to increase hydrocarbon recovery, and explores its feasibility with simulation work, compared with traditional water flooding method. The impact for the existence of natural fractures in tight oil reservoir is also studied in this work. Although requiring costly special equipment, a series of simulations prove that AIIP is a more reliable and efficient approach to increase the performance of fractured horizontal wells compared to conventional methods, oil recovery and oil rate were improved significantly after AIIP was conducted. Water injectivity increased sharply than traditional water flooding with a lower injection pressure. The existence of natural fracture in tight oil formation improved the water flow inside the formation, leading better sweep efficiency and higher oil recovery factor. However, water cut in producers increased faster in natural facture enriched model than that of basic model. Thereforem it is essential to evaluate the performance of AIIP process before application.
Abstract Over the past year and a half, the price of oil has plummeted from over $100 US per bbl in early 2014 to less than $47 US per bbl in the mid of 2017. In an attempt to sustain production without incurring significant additional expenditures, some operators may choose to implement enhanced oil recovery projects (such as waterflooding) while also utilizing existing infrastructure in the field. This paper focuses on one method of doing this by converting watered out or poor-performing horizontal production wells into horizontal water injection wells. The goal of this study was to create a screening criteria list which will enable assessment of a field to see if it could benefit from horizontal injection by way of converted horizontal production wells. The study began with a literature search to determine if a similar study had been conducted previously. When the study was found to be unique, the literature search then focused on understanding the background of horizontal water injection, along with case studies to see which conditions led to success or poor performance of horizontal water injection schemes. The applications, optimization techniques, evaluation methods and challenges involved in conversion of horizontal production wells to injectors and the horizontal injection process itself have been summarized and compiled into a screening criteria chart which can be broadly applied to any field to see if it is suitable for the proposed application. The screening process works by assigning zero, one, or two points to the response to a number of criteria regarding the reservoir, fluids, wells, and other information. A higher point value indicates a higher likelihood of a positive outcome if a horizontal production well is converted to a water injector.
Abstract This paper is a review of new well design and completion technologies utilized in the 2015 Lisburne drilling program in context of the historical development, most of which occurred in the 1985-1991 timeframe. The scope includes a comparative review of the new well program and design, as well as preliminary results. Lisburne is a low recovery, complex fractured carbonate field. Since the 1980s, attempts have been made to make the field more productive, including waterflooding and limited infill drilling. In 2015, the working interest owners of the field elected to employ well technologies that have matured since the initial field development. A U-shaped well design, with a swellpacker sliding sleeve completion, and a multi-stage acid and hydraulic fracture stimulation was utilized in the 2015 program, while the majority of the 1985-1991 historical development was with vertical wells with acid stimulations. Initial results show an approximate 10 times improvement in productivity index (PI) compared to the average well, access of multiple drainage intervals, and ability to successfully execute multistage acid and hydraulic fracture stimulations.
Imeh, Victoria Uduak (BP Exploration) | Robertson, Daniel Burton (BP) | Murray, Laurence Roderick (BP) | Lenig, David C. (BP Exploration (Alaska) Inc.) | Panda, Manmath Nath (Petrotechnical Resources-Alaska)
Abstract Thermal fracturing in water injectors plays a large role in controlling and determining injectivity. Vertical wells cannot always deliver the required rates to support offtake and achieve voidage replacement. Thus, horizontal wells are often selected to provide better sweep efficiency, and achieve higher injection rates than conventional vertical injectors. However, studies from Prudhoe Bay mature waterflood field indicate that these additional benefits can decline with time. A clearer understanding of the injection mechanism and an integrated solution was required to improve field injection performance. This paper presents field data on an injectivity study of several Prudhoe Bay injectors. Step rate tests results indicated no significant difference in injectivity between horizontal and conventional vertical injectors with time. It was concluded that the key to operating horizontal wells is achieving and maintaining fractures in multiple locations, and limiting fracture growth in the better quality rocks. In addition, water quality is crucial in attaining desired injection rate, fracture injectivity, and fracture growth. A recommended approach is presented in this paper which emphasises the need for a concise understanding of fracture characteristics in the reservoir for optimal injection performance. With the increasing need for water-flooding to access today's reserves and the rising costs in drilling horizontal injectors, this paper showcases the benefits of mitigating the decline in horizontal well injection performance with time. This is crucial for the proper distribution of water across the entire net interval reducing the risk of injectivity loss, and optimizing injection performance throughout the life of the field to achieving ultimate recovery. Introduction The Prudhoe Bay field, Alaska, is the largest oilfield in North America and has been in production since 1977. The Northwest Fault Block, originally containing 1.0 Billion STB of oil, is a structurally complex area bounded by faults on three sides and reservoir heterogeneity of fractures, high permeability streaks, layered reservoir and gravitational segregation. This area has lower pay Zones 2 and 3 (high quality) which are almost flooded out, and an upper Zone 4 (low quality) which contains the majority of the un-swept oil. Seawater injection ceased in 1996 and waterflooding was conducted solely with produced water thereafter. Due to vertical conformance issues, horizontal injectors were drilled and several of the existing vertical injectors were sidetracked as high angle or near horizontal wells to place injection into the un-swept upper Zone 4 Ivishak1. By accessing the remaining reserves in the lower permeability spots and careful well design and management, significant benefits have been delivered and field decline rate has been nearly halved from 19% to 10% per year. Waterflooding Challenges As the waterflood matured, waterflooding challenges became evident. From field data in Zone 4, it was observed that a conventional vertical injector could inject about 2000 to 3000 bwpd of produced water by injecting above fracture pressure. Above this rate, fracture growth becomes excessive and the well eventually loses rates to the more permeable Zone 3 connecting it to Zone 4. This has a negative impact on flood efficiency creating water cycling. Conversely, when produced water was injected into an unfractured cased and perforated well, the perforations plugged up with time, and injectivity declined unless the well was thermally fractured. This was evident in both vertical and horizontal wells. Moreover, step rate tests (SRT) on seven periphery injectors comparing horizontal and vertical completions indicated that there was no significant difference in their injectivities with time. Three of these wells were vertical injectors, Well A, Well B and Well D; the other four were horizontal injectors Well C, Well D-ST, Well E, and Well F. Vertical Injector Step Rate Test: Well A, a vertical injector which was drilled in April 1994, was perforated in Zone 4. Testing indicated out-of-zone injection in July 1999. It was squeezed in May 2000, however the well lost conformance again in May 2002. A temperature profile on Well B, a vertical injector, which was drilled in May 1994, also indicated out-of-zone injection in May 1998. SRT results for Wells A and B are shown in Figure 1. Following this the injection rate was set at 3000 bwpd for the wells.
Summary In this paper, we present the results of successful applications of polymer gels to control water production in Mexico. We discuss three case studies that used a systematic methodology to correctly diagnose near-wellbore water channeling behind the casing. The methodology uses diagnostic plots based on the historical behavior of the water/oil ratio (WOR) as a function of time. These include correlation with information from original cement bond logs (CBL's), oxygen-activated logs during production to effectively determine the origin of the water, and saturation logs to determine the water levels independent of the salinity of the water produced. In addition, we present successful applications of polymer gels to re-establish zonal isolations in the three case studies previously mentioned. We discuss gel placement and present the procedure followed in each case, evaluate a water injectivity test followed by a temperature log taken before gel placement to determine the height propagation of the water, and anticipate potential zone damage of adjacent producing intervals during gel placement. In one case, a new interval completed perforating through the gel with excellent results. Another case involved a zone abandonment with gel, in which positive pressure was tested with 35 and 70 kg/cm wellhead pressure at 2500 m. In all cases, the advantages of gel treatments over common cement squeezes are discussed. Finally, we present the treatment results, including the analysis of pressures recorded during gel placement and the oil and water production before and after treatment. Introduction One of the main problems encountered in old wells and wells originally cemented under low reservoir pressure consists of hydraulically isolating different intervals to allow proper production of the zones of interest. This lack of isolation has caused undesired fluid movement behind the casing, generating confusion about the actual levels of the oil/water contact (OWC) and causing premature abandonment of oil reserves. We present a methodology followed in northern Mexico that corrects water channeling behind the pipe with chromium-crosslinked polymer gels. The advantages of using gels over cement include their flexibility for pumping without a workover rig, higher control of setting time, ease of cleaning, lack of milling time, and superior operations cost without risking effective treatment. Included in our methodology is candidate selection with diagnostic plots that allow us to identify near-wellbore flow that correlates with CBL's, indicating poor cement. Finally, we discuss three field case studies in Poza Rica, northern Mexico. The data for each case are presented, including saturation logs, production logs, density logs, and water flow based on the activation of oxygen to monitor the movement of water through a channel. Corrections to water flow are also presented, as well as a detailed overview of the execution and results, showing treatment effectiveness. Near-Wellbore Flow The problems associated with water production and its control present a challenge to reservoir and workover engineers. The central issue lies in defining the source of the water and determining whether the water production of a given interval is necessary to the associated oil production. Therefore, we must define two kinds of water production - bad and good. The production of water is considered good when it sweeps an oil bank and carries important oil production with it. Bad water inhibits the oil production of an interval because of aquifer coning, injection-water channeling, or well-vicinity water flow. Therefore, knowing the source of the water produced is fundamental in defining the problem. The presence of water in a production interval brings questions about the actual level of the OWC. In many cases, this uncertainty causes premature abandonment of oil reserves assumed to be water-invaded. Near-wellbore flow (Fig. 1) is one of the most prominent causes of confusion because of several factors: poor cement bond, caverns formed by sand production, channels in the formation, natural fissures, hydraulic fractures, reduced oil flow caused by formation damage, and frequent stimulation in the near wellbore. Poor Cement Bond. Several factors may explain a poor cement bond. First is the exposure of the cement to adverse conditions of temperature, pressure, and perhaps sulfate waters, which cause the cement to deteriorate and create potential channels behind the pipe that can allow adverse fluids to flow. This is more likely to happen if problems such as low-pressure zones, gas migration, or poor design of washers and spacers were encountered during the primary cementing job. Today, this problem represents one of the most important causes of uncertainty regarding the OWC and a water-invaded interval. Caverns Formed by Sand Production. One of the main problems related to formations with sand production is that caverns can be created that can be detrimental to the hydraulic isolation of the production interval. This causes a potential for communication with a water-invaded zone. These problems are common in friable, poorly consolidated sandstone. Channels, Natural Fissures, and Hydraulic Fractures. Channels, natural fissures, or fractures in the formation create hydraulic communication through an interval. This may allow the water in a zone to percolate up to the production interval, negatively affecting the oil. The effect of natural fractures has been widely discussed in other publications.Fig. 2 illustrates channeling through a fracture. Critical production rates have a direct influence on the invasion of these channels by water and thus on its detrimental effect on oil production.
Abstract This paper describes a straightforward strategy for diagnosing and solving excess water production problems. The strategy advocates that the easiest problems should be attacked first and diagnosis of water production problems should begin with information already at hand. A listing of water production problems is provided, along with a ranking of their relative ease of solution. Conventional methods (e.g., cement, mechanical devices) normally should be applied first to treat the easiest problems-i.e., casing leaks and flow behind pipe where cement can be placed effectively and for unfractured wells where impermeable barriers separate water and hydrocarbon zones. Gelant treatments normally are the best option for casing leaks and flow behind pipe with flow restrictions that prevent effective cement placement. Both gelants and preformed gels have been successfully applied to treat hydraulic or natural fractures that connect to an aquifer. Treatments with preformed gels normally are the best option for faults or fractures crossing a deviated or horizontal well, for a single fracture causing channeling between wells, or for a natural fracture system that allows channeling between wells. Gel treatments should not be used to treat the most difficult problems—i.e., three-dimensional coning, cusping, or channeling through strata with crossflow. Introduction On average in the United States, more than seven barrels of water are produced for each barrel of oil. Worldwide, an average of three barrels of water are produced for each barrel of oil. The annual cost of disposing of this water is estimated to be 5–10 billion dollars in the US and around 40 billion dollars worldwide. Many different causes of excess water production exist (Table 1). Each of these problems requires a different approach to find the optimum solution. Therefore, to achieve a high success rate when treating water production problems, the nature of the problem must first be correctly identified. Many different materials and methods can be used to attack excess water production problems. Generally, these methods can be categorized as chemical or mechanical (see Table 2). Each of these methods may work very well for certain types of problems but are usually ineffective for other types of problems. Again, for effective treatment, the nature of the problem must first be correctly identified. Four problem categories are listed in Table 1 in the general order of increasing treatment difficulty. Within each category, the order of listing is only roughly related to the degree of treatment difficulty. Category A, "Conventional" Treatments Normally Are an Effective Choice, includes the application of water shutoff techniques that are generally well established, utilize materials with high mechanical strength, and function in or very near the wellbore. Examples include Portland cement, mechanical tubing patches, bridge plugs, straddle packers, and wellbore sand plugs. A few comments may be helpful to clarify some of the listings in Table 1. First, the difference between Problems 1 and 4 is simply a matter of aperture size of the casing leak and size of the flow channel behind the casing leak. Problem 1, involving casing leaks without flow restrictions, is where the leak is occurring through a large aperture breach in the piping (greater than roughly 1/8 in.) and a large flow conduit (greater than roughly 1/16 in.) behind the leak. The use of Portland cement is favored for treating Problem 1. Problem 4, involving casing leaks with flow restrictions, is where the leak is occurring through a small aperture breach (e.g., "pinhole" and tread leaks) in the piping (less than roughly 1/8 in.) and a small flow conduit (less than roughly 1/16 in.) behind the leak. The use of gel is favored to successfully treat Problem 4. In this paper, the gels under discussion may include those formed fromchemically crosslinking water-soluble organic polymers, water-based organic monomers, or silicates.
This paper was prepared for presentation at the 1999 SPE Annual Technical Conference and Exhibition held in Houston, Texas, 3–6 October 1999.
This paper was prepared for presentation at the 1999 SPE European Formation Damage Conference held in The Hague, The Netherlands, 31 May–1 June 1999.
Gheissary, G. (Shell RTS) | Fokker, P.A. (Netherlands Institute of Applied Geoscience TNO) | Egberts, P.J.P. (Netherlands Institute of Applied Geoscience TNO) | Floris, F.J.T. (Netherlands Institute of Applied Geoscience TNO) | Sommerauer, G. (Shell RTS) | Kenter, C.J. (Shell RTS)
The model still assumes that the In a recent study a numerical model for Produced Water Reinjection filtercake properties are determined by the cumulative volume (PWRI) under fracturing conditions was presented of solids pumped into the formation. This needs to be reviewed . The model was a 2-dimensional analytical fracture growth and possibly extended to also include immediate effects.